This section is intended to introduce the reader to various aspects of art, which may be associated with embodiments of the present invention. This discussion is believed to be helpful in providing the reader with information to facilitate a better understanding of particular techniques of the present invention. Accordingly, it should be understood that these statements are to be read in this light, and not necessarily as admissions of prior art.
Historically, there have been limited publications on the effect of changing ion composition for waterflooding of carbonate reservoirs. The process often caused problems in carbonate reservoirs due to adverse reactions between the injected water and anhydrite or gypsum which may exist in the carbonate reservoir. See Taber, J. J., and Martin, F. D., “Technical Screening Guides for the Enhanced Recovery of Oil”, SPE 12069, presented at SPE Annual Technical Conference and Exhibition, San Francisco, Calif., 5-8 Oct. 1983. The trend, however, has been changing recently due to an increased interest in enhanced waterflooding (EWF). A better than expected oil recovery at a fractured chalk reservoir at the Ekofisk field in the North Sea has provided some motivation for these studies. See, e.g., Puntervold, T., Strand, S., and Austad, T., “Coinjection of seawater and produced water to improve oil recovery from fractured North Sea chalk oil reservoirs,” Energy and Fuels, 23, 2527-2536 (2009); Strand, S., Puntervold, T., and Austad, T., “Effect of temperature on enhanced oil recovery from mixed-wet chalk cores by spontaneous imbibition and forced displacement using seawater,” Energy and Fuels, 22, 3222-3225 (2008); Tweheyo, M. T., Zhang, P., and Austad, T., “The Effects of Temperature and Potential Determining Ions Present in Seawater on Oil Recovery From Fractured Carbonates,” SPE 99438, SPE/DOE Symposium on Improved Oil Recovery, Tulsa, Okla., 22-26 Apr. 2006; Høgnesen , E. J., Strand, S., and Austad, T., “Waterflooding of Preferential Oil-Wet Carbonates: Oil Recovery Related to Reservoir Temperature and Brine Composition,” SPE 94166, presented at SPE EAGE Annual Conference, Madrid, Spain, 13-16 Jun., 2005; Zhang, P., Tweheyo, M. T., and Austad, T., “Wettability alteration and improved oil recovery in chalk: The effect of calcium in the presence of sulfate ,” Energy and Fuels, 20, 2056-2062 (2006); Zhang, P., Tweheyo, M. T., and Austad, T., “Wettability alteration and improved oil recovery by spontaneous imbibition of seawater into chalk: Impact of the potential determining ions Ca2+, Mg2+, and SO42−,” Colloids and Surfaces, 301,199-208 (2007). These articles are generally referred to herein as “the Austad studies.” The Austad studies focused on spontaneous imbibition tests for laboratory measurements with the goal of improving the imbibition processes suitable for fractured chalk reservoirs. Sulfate anions of various concentrations were added to sea water in those studies.
In addition, Ligthelm, D. L., Gronsveld, J., Hofman, J. P., Brussee, N. J., Marcelis, F., and van der Linde, H. A.: “Novel Waterflooding Strategy by Manipulation of Injection Brine Composition,” SPE 119835, presented in EUROPEC/EAGE Conference and Exhibition, Amsterdam, The Netherlands, 8-11 Jun., 2009 have performed spontaneous imbibition experiments on Middle Eastern limestone with 5% increment in oil recovery, giving a 17% total recovery of original oil-in-place (OOIP). However, Høgnesen , E. J., Strand, S., and Austad, T.: “Waterflooding of Preferential Oil-Wet Carbonates: Oil Recovery Related to Reservoir Temperature and Brine Composition,” SPE 94166, presented at SPE EAGE Annual Conference, Madrid, Spain, 13-16 Jun., 2005 have observed no effect of high sulfate brine during spontaneous imbibition on unfractured limestone treated with modified crude oil. As opposed to spontaneous imbibition studies, there have been few publications of laboratory coreflooding studies in which the waterflood performance is enhanced by adding inorganic salts for use in unfractured carbonates, such as limestones and dolomites, among others. In one such study, Bortolotti, V., Gottardi, G., Macini, P., and Srisuriyachai, F., “Intermittent Alkali Flooding in Vertical Carbonate Reservoir”, SPE 121832, presented at the SPE EUROPEC/EAGE Annual Conference and Exhibition held in Amsterdam, The Netherlands, 8-11 Jun. 2009, the authors discussed a technique for intermittent flow of an alkali solution for enhancing oil recovery. A concentrated alkali solution is injected into a reservoir, and the flow is intermittently paused before being resumed. The laboratory results showed a greater oil recovery than continuous flow without the pausing.
Previous published work has reported enhanced oil recovery by adding sulfate to the brine with chalk cores for both spontaneous imbibition and corefloods. See Høgnesen , E. J., Strand, S., and Austad, T.: “Waterflooding of Preferential Oil-Wet Carbonates: Oil Recovery Related to Reservoir Temperature and Brine Composition,” SPE 94166, presented at SPE EAGE Annual Conference, Madrid, Spain, 13-16 Jun., 2005; Strand, S., Puntervold, T., and Austad, T., “Effect of temperature on enhanced oil recovery from mixed-wet chalk cores by spontaneous imbibition and forced displacement using seawater,” Energy and Fuels, 22, 3222-3225 (2008); and Puntervold, T., Strand, S., and Austad, T.: “Coinjection of seawater and produced water to improve oil recovery from fractured North Sea chalk oil reservoirs,” Energy and Fuels, 23, 2527-2536 (2009). Other studies have examined spontaneous imbibition in limestone cores. See Ligthelm, D. L., Gronsveld, J., Hofman, J. P., Brussee, N. J., Marcelis, F., and van der Linde, H. A., “Novel Waterflooding Strategy by Manipulation of Injection Brine Composition,” SPE 119835, presented in EUROPEC/EAGE Conference and Exhibition, Amsterdam, The Netherlands, 8-11 Jun., 2009.
In contrast, a number of studies have focused on ion changes in concert with surfactant or polymer injection into reservoirs. For example, in Bortolotti, V., Macini, P., and Srisuriyachai, F., “Laboratory Evaluation of Alkali and Alkali-Surfactant-Polymer Flooding Combined with Intermittent Flow in Carbonate Rocks”, SPE 122499, presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition held in Jakarta, Indonesia, 4-6 Aug. 2009, the authors combined an alkali-surfactant-polymer flood with the intermittent or paused flow discussed previously. One set of results indicated that high alkali concentration, e.g., greater than about 0.5 molar alkali is not recommended, due to the formation of in-situ produced soap. Another set of results indicated that the highest final recovery may be obtained by injecting a surfactant, intermittently flowing an alkali solution through the reservoir, then flooding the reservoir with a polymer solution.
U.S. Patent Publication No. 2008/0011475 by Berger, et al. discloses an oil recovery method that uses amphoteric surfactants. The method is performed by injecting into an aqueous solution containing a mixture of amphoteric surfactants into one or more injection wells. The amphoteric surfactants have a hydrocarbyl chain length between 8 and 26, and some degree of unsaturation. Oil is recovered from one or more producing wells. The aqueous solution can also contain a thickening agent, an alkali, or a co-solvent.
International Patent Application Publication No. WO 2005/106192, by Austad, discloses a method for displacing petroleum from a carbonate rock. In the disclosed method, a positive electrical potential of the carbonate is reduced. This is performed by injecting a fluid that supplies negatively charged ions. As a result, the degree of recovery of petroleum is enhanced.
International Patent Application Publication No. WO 2008/029131, by Collins, et al., discloses a method for hydrocarbon recovery by waterflooding of a subterranean formation. The aqueous injection medium comprises a water soluble organic compound that contains an oxygen or nitrogen atom.
U.S. Pat. No. 4,074,755 to Hill, et al., discloses a waterflood process for recovering oil that is chemically aided and controlled by an ion exchange. The process involves successively injecting a chemical slug containing an active aqueous surfactant system or a thickened aqueous liquid, followed by an aqueous liquid into a reservoir. Generally the reservoir selected will have a significant amount of ion exchange capacity. The ionic composition of each injected fluid is adjusted to provide a ratio between the concentration of its effectively predominate monovalent cation and the square root of the concentration of its effectively predominate divalent cation. The ratio is selected to substantially match the ratio in the aqueous fluid immediately ahead of the injected fluid.
U.S. Pat. No. 4,714,113 to Mohnot, et al., discloses a technique for enhanced oil recovery using alkaline water flooding with a precipitation inhibitor. The waterflood injection fluid includes an alkali and a water-soluble precipitation inhibitor that can prevent divalent cations from precipitating. Beyond the immediate vicinity of the injection well, the permeability characteristics of the reservoir are modified by precipitation of divalent metal hydroxides or divalent metal carbonates.
U.S. Pat. No. 4,466,892 to Chan, et al., discloses a method for caustic flooding of a reservoir using a stabilized water. The stabilizer is a lignosulfonate material that is blended with the injection water before the addition of an alkaline chemical. The lignosulfonate prevents the formation of precipitates due to hydroxides.
U.S. Pat. No. 4,828,031 to Davis discloses a method for recovering oil from diatomite. In the method, a solvent is injected into a diatomite followed by an aqueous surfactant solution. The solution contains a diatomite/oil water wettability improving agent and an oil/water surface tension lowering agent.
U.S. Patent Application Publication No. 2007/0215351 by Wernli, et al., discloses the use of phosphorus and nitrogen containing formulations in secondary oil recovery operations. The phosphorous and nitrogen is generally in the form of ions, such as phosphate and ammonium ions, among others.
Many of the studies discussed above, however, focused on sand-based reservoirs and not carbonates. More recently, there have been a few studies investigating the effect of injecting low salinity water in carbonates. For example, Yousef, A. A., Al-Saleh, S, Al-Kaabi, A., and Al-Jawfi, M., “Laboratory Investigation of Novel Oil Recovery Method for Carbonate Reservoirs,” SPE 137634, presented at Canadian Unconventional Resources and International Petroleum Conference, Calgary, Canada, 19-21 Oct., 2010 investigated the effect of using diluted sea water as injection water in Middle East limestone cores. Significant uplifts, e.g., 18 to 19% OOIP additional oil recovery, have been measured and attributed to low salinity effects the study.
Alotaibi, M. B., Nasralla, R. A., and Nasr-El-Din, H. A., “Wettability Challenges in Carbonate Reservoirs,” SPE 129972, presented at SPE Improved Oil Recovery Symposium, Tulsa, Okla., 24-28 Apr. 2010, also studied salinity effects in Middle East limestone cores in corefloods, but reported inconclusive results.
Bagci, S., Mustafa, V. K., and Turksoy, U. “Effect of brine composition and alkali flood in the permeability damage of limestone reservoirs,” SPE 65394, presented at SPE International Symposium on Oilfield Chemistry, Houston, Tex., 13-16 Feb. 2001, studied the effect of brine salinity on oil recovery in unconsolidated limestone packs with Garzan crude oil. Bagci, et al., studied waterflood performance of various concentrations and combinations of KCl, NaCl, and CaCl2 brine. No definite low salinity effect was observed for unfractured limestones in that study. On the other hand, it has been known for over 50 years injecting low salinity water can have positive effects for some clastic reservoirs.
The improved oil recovery from varied waterflooding experiments has been attributed to a number of possible fundamental mechanisms. One leading theory, proposes that wettability alteration towards water-wet condition is the dominating mechanism for uplift in oil recovery for enhanced waterflood in carbonates. For example, in Webb, K. J., Black, C. J. J., and Tjetland, G., “A laboratory study investigating methods for improving oil recovery in carbonates” SPE 10506-MS, presented at the International Petroleum Technology Conference, 21-23 Doha, Qatar, November 2005, the authors presented capillary pressure curves measured during waterflood experiments on Valhall reservoir limestone cores at reservoir conditions. They observed that water-wetting characteristics of the studied rock increased after flooding with brine containing sulfate. They noted that sulfate was initially absent in both formation brine and the secondary injection brine. The increase in water-wetness was manifested as an increase in the positive part of the capillary pressure curve. In addition, in the Austad studies, in their work with chalk/limestone over the last ten years, the increased oil recovery in carbonate rock has been attributed to wettability alteration towards water-wetness.
While waterflooding has been used to enhance oil recovery, significant portions of the original oil in place is still left in the reservoir after conventional waterflooding techniques. Accordingly, the need exists for improved systems and methods of waterflooding a reservoir to recover still greater portions of the original oil in place. It will be easily understood that while increasing the percentage recovery by even 1-2% of the original oil in place (OOIP) may seem small in terms of percentages, the incremental improvement is significant both in terms of the improvement over the conventional techniques and in the improvement to the economies of a hydrocarbon recovery operation.
Further information may be found in at least in Hallenbeck, L. D., Sylte, J. E., Ebbs, D. J., and Thomas, L. K., “Implementation of the Ekofisk Field Waterflood,” SPE Formulation Evaluation, 6, 284-290 (1991); Lager, A., Webb, K. J., Black, C. J. J, Singleton, M., and Sorbie, K. S., “Low Salinity Oil Recovery—An Experimental Investigation,” presented at the International Symposium of the Society of Core Analysis, Trondheim, Norway, 12-16 Sep., 2006; Sylte, J. E., Hallenbeck, L. D., and Thomas, L. K., “Ekofisk Formation Pilot Waterflood,” SPE 18276, presented at SPE Annual Technical Conference and Exhibition, Houston, Tex., 2-5 Oct. 1988; Taber, J. J. and Martin, F. D., “Technical Screening Guides for the Enhanced Recovery of Oil”, SPE 12069, presented at SPE Annual Technical Conference and Exhibition, San Francisco Calif., 5-8 Oct. 1983; Verma, S., Adibhatla, B., Leahy-Dios, A., and Willingham, T., “Modeling Improved Recovery Methods in an Unstructured Grid Simulator”, presented at the International Petroleum Technology Conference, Doha, Qatar, 7-9 Dec., 2009.